U.S. patent application number 11/709551 was filed with the patent office on 2008-08-28 for crosslinked acids comprising derivatized xanthan and subterranean acidizing applications.
This patent application is currently assigned to Halliburton Energy Services, Inc.. Invention is credited to Thomas D. Welton.
Application Number | 20080202759 11/709551 |
Document ID | / |
Family ID | 39714579 |
Filed Date | 2008-08-28 |
United States Patent
Application |
20080202759 |
Kind Code |
A1 |
Welton; Thomas D. |
August 28, 2008 |
Crosslinked acids comprising derivatized xanthan and subterranean
acidizing applications
Abstract
Many methods are provided herein including, in one embodiment, a
method comprising: providing a fluid that comprises an acid,
crosslinked oxidized xanthan, and optionally, a base fluid; placing
the fluid in a well bore penetrating a subterranean formation; and
allowing the fluid to acidize at least a portion of the formation
or damage contained therein. In another embodiment, herein provided
is a fluid for subterranean uses comprising an acid and
crosslinked, oxidized xanthan.
Inventors: |
Welton; Thomas D.; (Duncan,
OK) |
Correspondence
Address: |
ROBERT A. KENT
P.O. BOX 1431
DUNCAN
OK
73536
US
|
Assignee: |
Halliburton Energy Services,
Inc.
|
Family ID: |
39714579 |
Appl. No.: |
11/709551 |
Filed: |
February 22, 2007 |
Current U.S.
Class: |
166/308.5 ;
166/307; 166/310; 507/201; 507/213; 507/260; 507/269; 507/271 |
Current CPC
Class: |
C23F 11/04 20130101;
C23F 11/173 20130101; C09K 8/74 20130101 |
Class at
Publication: |
166/308.5 ;
166/307; 166/310; 507/201; 507/213; 507/260; 507/269; 507/271 |
International
Class: |
E21B 43/27 20060101
E21B043/27; C09K 8/60 20060101 C09K008/60; C23F 11/18 20060101
C23F011/18; E21B 43/25 20060101 E21B043/25 |
Claims
1. A method comprising: providing a fluid that comprises an acid,
crosslinked oxidized xanthan, and optionally, a base fluid, placing
the fluid in a well bore penetrating a subterranean formation; and
allowing the fluid to acidize at least a portion of the formation
or damage contained therein.
2. The method of claim 1 wherein the fluid further comprise at
least one additional component chosen from the group consisting of:
a gelling agent; a diverting agent; a particulate solid diverting
agent; a degradable particulate diverting material; a
self-degradable particulate diverting material; a mechanical
diverting agent; a surfactant; a viscoelastic surfactant; a
bactericide; a nonemulsifier; a second acid; a crosslinking agent;
a mutual solvent; a fluid loss control agent; a proppant
particulate; a pH-adjusting agent; a pH-buffer; an oxidizing agent;
an enzyme; a lost circulation material; a scale inhibitor; a
surfactant; a clay stabilizer; a corrosion inhibitor; a paraffin
inhibitor; an asphaltene inhibitor; a penetrating agent; a clay
control additive; an iron control additive; a chelator; a reducer;
an oxygen scavenger; a sulfide scavenger; an emulsifier; a foamer;
a gas; a breaker; an iron control additive; a derivative thereof;
and a combination thereof.
3. The method of claim 1 wherein the acid comprises an acid chosen
from the group consisting of: organic acids; inorganic acids;
hydrochloric acid; hydrofluoric acid; formic acid; lactic acid;
phosphoric acid; sulfamic acid; acetic acid; derivatives thereof;
and combinations thereof.
4. The method of claim 1 wherein the oxidized xanthan becomes
crosslinked after being placed in a well bore.
5. The method of claim 1 wherein the oxidized xanthan becomes
crosslinked before being placed in a well bore.
6. The method of claim 1 wherein the crosslinked oxidized xanthan
has been oxidized in a process involving an oxidizer chosen from
the group consisting of: salts of perborates; salts of
permanganates; salts of percarbonates; salts of periodates; salts
of hypochlorite; sodium perborate; sodium persulfate; potassium
persulfate; ammonium persulfate; sodium permanganate; potassium
permanganate; magnesium permanganate; calcium permanganate; sodium
percarbonate; potassium percarbonate; sodium periodate; potassium
periodate; sodium hypochlorite; hydrogen peroxide; calcium
peroxide;magnesium peroxide; derivatives thereof; and combinations
thereof.
7. The method of claim 1 wherein the crosslinked oxidized xanthan
is pre-oxidized before taking it to a well site.
8. The method of claim 1 wherein the crosslinked xanthan has been
crosslinked by use of a crosslinking agent chosen from the group
consisting of: zirconium compounds; zirconium lactate; zirconium
lactate triethanolamine; zirconium carbonate; zirconium
acetylacetonate; zirconium maleate; zirconium citrate; zirconium
oxychloride; zirconium diisopropylamine lactate; titanium
compounds; titanium lactate; titanium maleate; titanium citrate;
titanium ammonium lactate; titanium triethanolamine; titanium
acetylacetonate; aluminum compounds; aluminum lactate; aluminum
citrate; borate compounds; sodium tetraborate; boric acid; disodium
octaborate tetrahydrate; sodium diborate; ulexite; colemanite;
antimony compounds; chromium compounds; iron compounds; iron
chloride; copper compounds; zinc compounds; divalent ions; calcium
chloride; magnesium oxide; derivatives thereof; and combinations
thereof.
9. The method of claim 1 wherein the base fluid is an aqueous-based
fluid.
10. A method comprising: providing a fluid that comprises an acid,
crosslinked oxidized xanthan, and optionally, a base fluid, and
placing the fluid in a well bore penetrating a subterranean
formation at a pressure sufficient to create or enhance a fracture
in the subterranean formation.
11. The method of claim 8 wherein the fluid is placed in the well
bore as part of a matrix acidizing application; an acidizing
applications; a fracture acidizing application; a scale removal
application; a damage removal application; a hydrate treatment
application; a hydrate inhibition application; or an open hole
diversion application.
12. The method of claim 1 wherein the acid comprises an acid chosen
from the group consisting of: organic acids; inorganic acids;
hydrochloric acid; hydrofluoric acid; formic acid; lactic acid;
phosphoric acid; sulfamic acid; acetic acid; derivatives thereof;
and combinations thereof.
13. The method of claim 1 wherein the oxidized xanthan becomes
crosslinked after being placed in a well bore.
14. The method of claim 1 wherein the crosslinked oxidized xanthan
has been oxidized in a process involving an oxidizer chosen from
the group consisting of: salts of perborates; salts of
permanganates; salts of percarbonates; salts of periodates; salts
of hypochlorite; sodium perborate; sodium persulfate; potassium
persulfate; ammonium persulfate; sodium permanganate; potassium
permanganate; magnesium permanganate; calcium permanganate; sodium
percarbonate; potassium percarbonate; sodium periodate; potassium
periodate; sodium hypochlorite; hydrogen peroxide; calcium
peroxide; magnesium peroxide; derivatives thereof; and combinations
thereof.
15. The method of claim 1 wherein the crosslinked oxidized xanthan
is pre-oxidized before taking it to a well site.
16. The method of claim 1 wherein the crosslinked xanthan has been
crosslinked by use of a crosslinking agent chosen from the group
consisting of: zirconium compounds; zirconium lactate; zirconium
lactate triethanolamine; zirconium carbonate; zirconium
acetylacetonate; zirconium maleate; zirconium citrate; zirconium
oxychloride; zirconium diisopropylamine lactate; titanium
compounds; titanium lactate; titanium maleate; titanium citrate;
titanium ammonium lactate; titanium triethanolamine; titanium
acetylacetonate; aluminum compounds; aluminum lactate; aluminum
citrate; borate compounds; sodium tetraborate; boric acid; disodium
octaborate tetrahydrate; sodium diborate; ulexite; colemanite;
antimony compounds; chromium compounds; iron compounds; iron
chloride; copper compounds; zinc compounds; divalent ions; calcium
chloride; magnesium oxide; derivatives thereof; and combinations
thereof.
17. A method comprising: providing a fluid that comprises an acid,
crosslinked oxidized xanthan, and optionally, a base fluid; placing
the fluid into a subterranean formation; allowing the fluid to
contact scale in the well bore or near well bore region; and
allowing the acid to react with the scale.
18. The method of claim 1 wherein the oxidized xanthan becomes
crosslinked after being placed in a well bore.
19. The method of claim 1 wherein the crosslinked oxidized xanthan
has been oxidized in a process involving an oxidizer chosen from
the group consisting of: salts of perborates; salts of
permanganates; salts of percarbonates; salts of periodates; salts
of hypochlorite; sodium perborate; sodium persulfate; potassium
persulfate; ammonium persulfate; sodium permanganate; potassium
permanganate; magnesium permanganate; calcium permanganate; sodium
percarbonate; potassium percarbonate; sodium periodate; potassium
periodate; sodium hypochlorite; hydrogen peroxide; calcium
peroxide; magnesium peroxide; derivatives thereof; and combinations
thereof.
20. The method of claim 1 wherein the crosslinked oxidized xanthan
is pre-oxidized before taking it to a well site.
21. The method of claim 1 wherein the crosslinked xanthan has been
crosslinked by use of a crosslinking agent chosen from the group
consisting of: zirconium compounds; zirconium lactate; zirconium
lactate triethanolamine; zirconium carbonate; zirconium
acetylacetonate; zirconium maleate; zirconium citrate; zirconium
oxychloride; zirconium diisopropylamine lactate; titanium
compounds; titanium lactate; titanium maleate; titanium citrate;
titanium ammonium lactate; titanium triethanolamine; titanium
acetylacetonate; aluminum compounds; aluminum lactate; aluminum
citrate; borate compounds; sodium tetraborate; boric acid; disodium
octaborate tetrahydrate; sodium diborate; ulexite; colemanite;
antimony compounds; chromium compounds; iron compounds; iron
chloride; copper compounds; zinc compounds; divalent ions; calcium
chloride; magnesium oxide; derivatives thereof; and combinations
thereof.
Description
BACKGROUND
[0001] The present invention relates to methods of acidizing
subterranean formations or well bores, and more specifically, to
acidizing fluids involving in-situ crosslinked spent acids and
crosslinked live acids comprising derivatized xanthan for
subterranean acidizing applications. These acidizing fluids may be
used in any suitable acidizing treatment to acidize a portion of a
subterranean formation or any damage contained therein. The term
"damage" as used herein refers to undesirable deposits in a
subterranean formation that may reduce its permeability. Scale,
skin, and hydrates are contemplated by this term. Also contemplated
by this term are geological deposits, such as but not limited to,
carbonates located on the pore throats of the sandstone in a
subterranean formation.
[0002] Acidizing and fracturing treatments using aqueous acidic
solutions commonly are carried out in subterranean formations
(including those that contain hydrocarbons as well as those that do
not) penetrated by well bores to accomplish a number of purposes,
one of which is to increase the permeability of the formation. The
resultant increase in formation permeability normally results in an
increase in the recovery of hydrocarbons from the formation.
[0003] Acidizing techniques can be carried out as "matrix
acidizing" procedures or as "acid fracturing" procedures.
Generally, in acidizing treatments, aqueous acidic solutions are
introduced into a subterranean formation under pressure so that the
acidic solution flows into the pore spaces of the formation to
remove near-well formation damage and other damaging substances.
The acidic solution reacts with acid-soluble materials contained in
the formation which results in an increase in the size of the pore
spaces and an increase in the permeability of the formation. This
procedure commonly enhances production by increasing the effective
well radius. When performed at pressures above the pressure
required to fracture the formation, the procedure is often referred
to as acid fracturing. Fracture-acidizing involves the formation of
one or more fractures in the formation and the introduction of an
aqueous acidizing fluid into the fractures to etch the fractures'
faces whereby flow channels are formed when the fractures close.
The aqueous acidizing fluid also enlarges the pore spaces in the
fracture faces and in the formation. In fracture-acidizing
treatments, one or more fractures are produced in the formation and
the acidic solution is introduced into the fracture to etch flow
channels in the fracture face. The acid also enlarges the pore
spaces in the fracture face and in the formation. The use of the
term "acidizing" herein refers to both types of acidizing
treatments, and more specifically, refers to the general process of
introducing an acid down hole to perform a desired function, e.g.,
to acidize a portion of a subterranean formation or any damage
contained therein.
[0004] Although acidizing a portion of a subterranean formation can
be very beneficial in terms of permeability, conventional acidizing
fluids can have significant drawbacks. One major problem associated
with conventional acidizing treatment fluids is that deeper
penetration into the formation is not usually achievable because,
inter alia, the acid may be spent before it can deeply penetrate
into the subterranean formation. The rate at which acidizing fluids
react with reactive materials in the subterranean formation is a
function of various factors including, but not limited to, acid
concentration, temperature, fluid velocity, mass transfer, and the
type of reactive material encountered. Whatever the rate of
reaction of the acidic solution, the solution can be introduced
into the formation only a certain distance before it becomes spent.
For instance, conventional acidizing fluids, such as those that
contain organic acids, hydrochloric acid or a mixture of
hydrofluoric and hydrochloric acids, have high acid strength and
quickly react with the formation itself, fines and damage nearest
the well bore, and do not penetrate the formation to a desirable
degree before becoming spent. To achieve optimal results, it is
desirable to maintain the acidic solution in a reactive condition
for as long a period of time as possible to maximize the degree of
penetration so that the permeability enhancement produced by the
acidic solution may be increased.
[0005] Another problem associated with some current acidizing
fluids for subterranean formations is that synthetic polymers or
surfactants are utilized to gel acidizing fluids. For instance, to
obtain a delayed gel, only a few surfactant gels and polymer fluids
will work. Moreover, generally, it is desirable in acidizing for
the synthetic polymer to crosslink upon spending so that it may
divert the unspent acid into a new portion of the formation. Thus,
synthetic polymers are usually the preferred choice for such
applications due to the wide range of temperatures at which they
function and their ability to tolerate many additives. Note,
though, some viscoelastic surfactants are another choice, but may
suffer from compatibility issues with additives. Natural
biopolymers are thought to be poor choices for crosslinked gel
acidizing applications due to the relatively low temperatures they
were believed to function at and their relatively poor cross
linking ability.
[0006] Despite the advantages of using gelling agents in acid
treatments, using such gelling agents may be problematic. For
example, conventional polymeric gelling agents may leave an
undesirable residue in the subterranean formation after use. As a
result, potentially costly remedial operations may be required to
clean up the surfaces inside the subterranean formation. Foamed
treatment fluids and emulsion-based treatment fluids have been
employed to minimize residual damage, but increased expense and
complexity often result.
[0007] Biopolymers such as xanthan would be more desirable to use
due to their degradability characteristics. Early experimentation,
however, with xanthan yielded less than satisfactory gels. These
gels tended to break or undergo syneresis easily, and often looked
curdled with a cottage cheese-like consistency. Crosslinking
xanthan can be especially difficult and/or impractical because the
resultant crosslinked structure has been thought to be unusable and
can have strange rheological properties.
SUMMARY
[0008] The present invention relates to methods of acidizing
subterranean formations or well bores, and more specifically, to
acidizing fluids involving in-situ crosslinked spent acids and
crosslinked live acids comprising derivatized xanthan for
subterranean acidizing applications. These acidizing fluids may be
used in any suitable acidizing treatment to acidize a portion of a
subterranean formation or any damage contained therein.
[0009] In one embodiment, the present invention provides a method
comprising: providing a fluid that comprises an acid, crosslinked
oxidized xanthan, and optionally, a base fluid; placing the fluid
in a well bore penetrating a subterranean formation; and allowing
the fluid to acidize at least a portion of the formation or damage
contained therein.
[0010] In one embodiment, the present invention provides a method
comprising: providing a fluid that comprises an acid, crosslinked
oxidized xanthan, and optionally, a base fluid; and placing the
fluid in a well bore penetrating a subterranean formation at a
pressure sufficient to create or enhance a fracture in the
subterranean formation.
[0011] In one embodiment, the present invention provides a method
comprising: providing a fluid that comprises an acid, crosslinked
oxidized xanthan, and optionally, a base fluid; placing the fluid
into a subterranean formation; allowing the fluid to contact scale
in the well bore or near well bore region; and allowing the acid to
react with the scale.
[0012] In one embodiment, the present invention provides a method
comprising: providing a fluid that comprises an acid, oxidized
xanthan, and optionally, a base fluid; placing the fluid in a well
bore penetrating a subterranean formation; and allowing the fluid
to acidize at least a portion of the formation or damage contained
therein.
[0013] In one embodiment, the present invention provides a fluid
for subterranean uses comprising crosslinked, oxidized xanthan.
[0014] In one embodiment, the present invention provides a fluid
for subterranean uses comprising oxidized xanthan.
[0015] In one embodiment, the present invention provides a
composition comprising oxidized, crosslinked xanthan.
[0016] The features and advantages of the present invention will be
readily apparent to those skilled in the art. While numerous
changes may be made by those skilled in the art, such changes are
within the spirit of the invention.
DESCRIPTION OF PREFERRED EMBODIMENTS
[0017] The present invention relates to methods of acidizing
subterranean formations or well bores, and more specifically, to
acidizing fluids involving in-situ crosslinked spent acids and
crosslinked live acids comprising derivatized xanthan for
subterranean acidizing applications. These acidizing fluids may be
used in any suitable acidizing treatment to acidize a portion of a
subterranean formation or any damage contained therein.
[0018] The compositions and methods of the present invention may be
used in matrix acidizing applications, acidizing applications,
fracture acidizing applications, scale removal applications, damage
removal applications, hydrate treatment applications, and hydrate
inhibition applications. They may also be used in open hole
diversion applications.
[0019] Among the many potential benefits of the present invention,
one advantage may be that the acidizing fluids of the present
invention should achieve deeper penetration into the subterranean
formation from the well bore. Additionally, longer effective
fracture acidizing lengths should be realized at least in most
embodiments than compared to ungelled acids. Another benefit may be
that leak off may be less as compared to conventional ungelled
acidic fluids. One of the more important benefits should be that
deeper penetration of the acid into the subterranean formation
should be obtained. Additionally, in certain embodiments, the
acidizing fluids of the present invention should effectively
generate wormholes to stimulate production in subterranean
carbonate formations, dissolve damage, and remove fines to recover
production in formations at elevated temperatures. Another
potential benefit is that the these acidizing fluids should not
leave undesirable residue like many synthetic polymers do, which
could lead to easier and better clean-up. Other advantages and
objects of the present invention may be evident to one skilled in
the art with the benefit of this disclosure.
[0020] In certain embodiments, the acidizing fluids of the present
invention comprise an acid, an oxidized crosslinked xanthan, and
optionally, a base fluid.
[0021] If desired, acidizing fluids of the present invention also
may comprise other gelling agents, diverting agents,
nonemulsifiers, other acids, cross linking agents, and/or mutual
solvents. Combinations and derivatives of these also may be
suitable. Although some fluid loss control agents may be used if
needed, in the fluids of the present invention there should be less
need for additional fluid loss control because the fluids can
crosslink. This may be application dependent. Any fluid loss may
affect the ability to create longer fractures. Any sort of proppant
particulates may be included if desired as well. The acidizing
fluids of the present invention may further comprise additional
additives as deemed appropriate by one of ordinary skill in the
art, with the benefit of this disclosure. Examples of such
additional additives include, but are not limited to, pH-adjusting
agents, pH-buffers, oxidizing agents, enzymes, lost circulation
materials, scale inhibitors, surfactants, clay stabilizers,
corrosion inhibitors, paraffin inhibitors, asphaltene inhibitors,
penetrating agents, clay control additives, iron control additives,
chelators, reducers, oxygen scavengers, sulfide scavengers,
emulsifiers, foamers, gases, derivatives thereof and combinations
thereof, and the like.
[0022] Any acid suitable for use in subterranean applications may
be used in conjunction with the present invention. The acid may
comprise organic acids, inorganic acids, derivatives thereof, or
combinations thereof. Examples of suitable acids include, but are
not limited to, hydrochloric acid, hydrofluoric acid, formic acid,
lactic acid, phosphoric acid, sulfamic acid, acetic acid,
derivatives thereof, and mixtures thereof. In certain embodiments,
the acid may be present in the treatment fluids in an amount of
from about 0.5% to about 40% by weight of the fluid. In certain
embodiments, the acid may be present in the treatment fluids of the
present invention in an amount of from about 2.5% to about 28% by
weight of the fluid. In other embodiments, the acid may be present
in the treatment fluids of the present invention in an amount of
from about 2.5% to about 15% by weight of the fluid. Individuals
skilled in the art, with the benefit of this disclosure, will be
able to select a suitable acid and a suitable concentration thereof
for a chosen application. In some instances, the particular
concentration used in any particular embodiment depends on what
acid is being used, and what percentage of acid is present. Other
complex, interrelated factors that may be considered in deciding
how much of the acid compound to use include, but are not limited
to, the composition of the formation, the temperature of the
formation, the pressure of the formation, the particular fines and
damage present in the formation (e.g., scale, skin, calcium
carbonate, silicates, and the like), the particular acid used,
metals the acid may contact, corrosion concerns, the expected
contact time of the acid with the formation, etc. The desired
contact time also depends on the particular application and
purpose. For example, if very delayed acidizing is desired, then it
may be desirable to pump a dilute, low concentration but a high
volume to get deeper penetration. For matrix stimulation
treatments, the expected contact time may be determined from the
maximum pumping rate that does not cause the down hole pressure to
exceed the fracturing pressure. For damage or fines removal
procedures, the expected contact time may be based on laboratory
tests, but usually should allow for extended contact periods as
compared to conventional acid treatments. For instance, in
conventional treatments where a live acid is pumped to remove scale
or fines, that acid may react instantaneously so clean up of the
entire amount of damage and fines may be impossible. Possibly, to
achieve an equivalent of a 15% HCl acidizing treatment, it may be
desirable to run formates and acetates mixtures, depending on which
ones are chosen with an eye toward the reactivity of the formation
at a given temperature. To avoid undesirable salt precipitation
problems, it may be desirable to combine formates and acetates or
lactates to keep both below the over saturation concentration that
would cause salts to precipitate in formation, but still achieve
the acid potential and dissolving power necessary for the job. To
choose the appropriate acid and the right concentration of that
acid, one should balance salt precipitation and acid dissolving
power concentration concerns. In some embodiments, a combination of
acetic acid and formic or a combination of acetic acid and lactic
acid may be preferred over a combination of acetic acid and formic
acid and lactic acid. One of ordinary skill in the art with the
benefit of this disclosure should know how to balance the factors
so that salts do not saturate.
[0023] The acidizing fluids of the present invention comprise
crosslinked oxidized xanthan, which, inter alia, acts as a gelling
agent to viscosity the fluid. Preferably, the xanthan polymer used
is of high purity. One of ordinary skill in the art with the
benefit of this disclosure will recognize the grade of purity of
xanthan polymer appropriate for a particular application. An
example of a suitable source of xanthan polymer is commercially
available from Kelco Oil Field Group, of Houston, Tex., under the
tradename "XANVIS L." An example of another suitable source of
xanthan polymer is commercially available from Halliburton Energy
Services, Inc., of Duncan, Okla., under the tradename "WG-24." An
example of another suitable source of xanthan polymer is
commercially available from Halliburton Energy Services, Inc., of
Duncan, Okla., under the tradename "WG-37." The amount of oxidized
xanthan to include in a fluid of the present invention will depend
on several factors including, but not limited to the desired
viscosity of the fluid, the characteristics of the formation, the
characteristics of the acidizing application, etc. Preferred
xanthans are disclosed in U.S. Published Patent Application No.
2006/0014648, which is incorporated herein by reference. Other
considerations will be known to those skilled in the art with the
benefit of this disclosure. In some embodiments, the amount may
range from about 10 to about 200 lbs/1000 gallons of the fluid. In
other embodiments, the amount may range from about 20 to about 160
lbs/1000 gallons of fluid.
[0024] Suitable oxidizers for oxidizing the xanthan polymer
include, but are not limited to, salts of perborates, salts of
permanganates, salts of percarbonates, salts of periodates, salts
of hypochlorite, sodium perborate, sodium persulfate, potassium
persulfate, ammonium persulfate, sodium permanganate, potassium
permanganate, magnesium permanganate, calcium permanganate, sodium
percarbonate, potassium percarbonate, sodium periodate, potassium
periodate, sodium hypochlorite, hydrogen peroxide, calcium
peroxide, and magnesium peroxide. Derivatives and combinations of
these may also be suitable. To oxidize the xanthan, in certain
embodiments, the oxidizer may used in an amount of from about 0.01%
to about 50% based on the amount of the xanthan present. A more
preferred range would be from about 0.1 to about 10% and an even
more preferred would be from about 0.5 to about 5% Generally
speaking, one thing to be mindful of is that the more oxidizer
used, the faster the oxidation reaction will be.
[0025] In some embodiments, the xanthan polymer may be pre-oxidized
and taken in its oxidized form to a well site for use in a
subterranean application. In other instances, the xanthan may be
oxidized at the well site. However, it is preferred that the
oxidizer be added to the xanthan before the acid is added to the
xanthan even if the xanthan is oxidized at the well site.
[0026] At least a portion of the oxidized xanthan included in the
fluids of the present invention may be crosslinked by a reaction
comprising a crosslinking agent, e.g., to further increase the
treatment fluid's viscosity thereof. The oxidized xanthan can be
crosslinked before the fluid is placed in a well bore or at any
other suitable time. Crosslinking agents typically comprise at
least one metal ion that is capable of crosslinking polymer
molecules. Really there are an unlimited number of crosslinking
agents that may be suitable because the compositions of the present
invention are not limited by ligand choice on the crosslinking
agent. Examples of suitable crosslinking agents include, but are
not limited to, zirconium compounds (such as, for example,
zirconium lactate, zirconium lactate triethanolamine, zirconium
carbonate, zirconium acetylacetonate, zirconium maleate, zirconium
citrate, zirconium oxychloride, and zirconium diisopropylamine
lactate); titanium compounds (such as, for example, titanium
lactate, titanium maleate, titanium citrate, titanium ammonium
lactate, titanium triethanolamine, and titanium acetylacetonate);
aluminum compounds (such as, for example, aluminum lactate or
aluminum citrate); borate compounds (such as, for example, sodium
tetraborate, boric acid, disodium octaborate tetrahydrate, sodium
diborate, ulexite, and colemanite); antimony compounds; chromium
compounds; iron compounds; copper compounds; zinc compounds; or
derivatives and combinations thereof. An example of a suitable
commercially available zirconium-based cross linking agent is
"CL-24.TM." cross linker from Halliburton Energy Services, Inc.,
Duncan, Okla. An example of a suitable commercially available
titanium-based cross linking agent is "CL-39.TM." cross linker from
Halliburton Energy Services, Inc., Duncan Oklahoma. An example of a
suitable borate-based cross linking agent is commercially available
as "CL-22.TM." delayed borate cross linker from Halliburton Energy
Services, Inc., Duncan, Okla. Divalent ions also may be used; for
example, calcium chloride and magnesium oxide. An example of a
suitable divalent ion cross linking agent is commercially available
as "CL-30.TM." from Halliburton Energy Services, Inc., Duncan,
Okla. Another example of a suitable cross linking agent is "CL-15,"
from Halliburton Energy Services, Inc., Duncan Okla. Where present,
the cross linking agent generally should be included in the fluids
of the present invention in an amount sufficient, among other
things, to provide the desired degree of cross linking. In some
embodiments, the cross linking agent may be present in the
treatment fluids of the present invention in an amount in the range
of from about 0.01% to about 5% by weight of the treatment fluid.
Buffering compounds may be used if desired, e.g., to delay or
control the cross linking reaction. These may include glycolic
acid, lactic acid, carbonates, bicarbonates, acetates, phosphates,
and any other suitable buffering agent.
[0027] Preferred crosslinking agents are iron compounds such as
iron chloride. When an iron compound is used, one can achieve a
delayed crosslink (or one that crosslinks in-situ). Using a delayed
crosslinked acid as opposed to a crosslinked "live" acid (e.g., one
that has been crosslinked prior to the acid substantially spending)
may have several benefits. Delayed crosslinked acids may be more
pumpable than crosslinked live acid acidizing fluids. One possible
limitation of crosslinked live acid acidizing fluids is that they
may have high viscosity that may lead to increased frictional
pressures during pumping, which may require greater pumping
horsepower. Also, fully crosslinked live acids are not always
necessary to retard the reaction of strong acids on carbonates;
merely viscosifying the acid can provide ample retardation.
However, in such treatments much of the acid may be lost as a
result of leak-off through wormholes. When using a delayed
crosslinked fluid, fluid loss can be controlled as the acid leaks
off through wormholes and spends. When the acid is nearly spent,
the system may crosslink, thereby blocking wormholes and preventing
further loss of acid from the fracture face. Additionally, this
type of fluid typically will not break until the acid is
substantially spent.
[0028] One should note that including a suitable breaker in an
acidizing fluid of the present invention or adding a suitable
breaker to an acidizing fluid of the present invention may be
advisable depending on the xanthan and its interaction with the
acid and the well bore conditions. A breaker or breaker aid may be
advisable to ultimately reduce the viscosity of the fluid. Any
breaker suitable for the subterranean formation and the xanthan may
be used. The amount of a breaker to include will depend, inter
alia, on the amount of xanthan present in the treatment fluid.
Other considerations regarding the breaker are known to one skilled
in the art with the benefit of this disclosure.
[0029] Optionally, an iron control additive may be used in
conjunction with the acidizing fluids of the present invention to
prevent potential precipitation of the iron. Typical examples
include, but are not limited to, citric acid,
ethylenediaminetetraacetic acid, nitrilotriacetic acid, and
erythorbic acid, and salts thereof. The amount of an iron control
additive to include will depend, inter alia, on the amount of
potential iron precipitates present in the treatment fluid. Other
considerations regarding the iron control additive are known to one
skilled in the art with the benefit of this disclosure
[0030] If used, the base fluid is preferably aqueous-based. A base
fluid may be beneficially used, for example, to provide dilution to
control concentration or coverage issues. One of ordinary skill in
the art with the benefit of this disclosure will recognize when a
base fluid may be beneficial. The base fluid should be chosen based
on its compatibility with the formation and the acid used. Suitable
base fluids include fresh water, brines, seawater, or any other
type of aqueous-fluid suitable for subterranean uses. The amount of
base fluid used is typically dictated by the final concentration of
acid desired and the concentration of the acid source. One of
ordinary skill in the art with the benefit of this disclosure ill
recognize the appropriate amount of base fluid to include to reach
the final concentrations desired for a chosen application.
[0031] In order to insure that the producing zone is contacted by a
fluid of the present invention uniformly, a supplemental
particulate solid diverting agent may be placed in the well bore or
the formation to isolate the zone of interest. The term "zone" as
used herein simply refers to a portion of the formation and does
not imply a particular geological strata or composition. One
suitable technique involves packing the diverting agent in
perforation tunnels extending from the well bore into the
subterranean zone. The diverting agent in the perforation tunnels
causes the fluid introduced therein to be uniformly distributed
between all of the perforations whereby the subterranean zone is
uniformly treated. The particulate solid diverting agent should be
subsequently removed from the perforation tunnel to allow the
maximum flow of produced hydrocarbons from the subterranean zone
into the well bore. This can be accomplished by contacting the
particulate solid diverting agent with a fluid which degrades the
diverting agent, such as, water, oil, xylene and the like. Other
chemical diverting agents that are suitable for use in this
invention include oil-soluble resins, water-soluble rock salts, and
emulsions.
[0032] Degradable particulate diverting materials are also suitable
for use in the present invention. The degradable particulate
diverting materials of this invention can be placed in the
subterranean zone or packed into perforation tunnels in the
subterranean zone by introducing a carrier fluid containing the
degradable particulate diverting materials into the subterranean
zone. Preferred degradable particulate diverting materials may
comprise a degradable material which is capable of degrading over
time when placed in a subterranean zone and will not recrystallize
or otherwise solidify down hole. The degradable particular
diverting materials may need a source of water to degrade and this
may be provided by a particulate hydrated organic or inorganic
solid compounds introduced into the subterranean formation either
before, during or after the degradable particulate diverting
material is introduced. Nonlimiting examples of degradable
particulates that may be used in conjunction with the compositions
and methods of the present invention include but are not limited to
degradable polymers. The term "particulate" as used herein is
intended to include material particles having the physical shape of
platelets, shavings, flakes, ribbons, rods, strips, spheroids,
toroids, pellets, tablets or any other physical shape. The terms
"degrade," "degradation," "degradable," and the like when used
herein refer to both the two relative cases of hydrolytic
degradation that the degradable particulate may undergo, i.e.,
heterogeneous (or bulk erosion) and homogeneous (or surface
erosion), and any stage of degradation in between these two. This
degradation can be a result of inter alia, a chemical or thermal
reaction or a reaction induced by radiation. Suitable examples of
degradable polymers that may be used in accordance with the present
invention include but are not limited to those described in the
publication of Advances in Polymer Science, Vol. 157 entitled
"Degradable Aliphatic Polyesters" edited by A.-C. Albertsson.
Specific examples include homopolymers, random, block, graft, and
star- and hyper-branched aliphatic polyesters. Polycondensation
reactions, ring-opening polymerizations, free radical
polymerizations, anionic polymerizations, carbocationic
polymerizations, coordinative ring-opening polymerizations, and any
other suitable process may prepare such suitable polymers. Specific
examples of suitable polymers include polysaccharides such as
dextran or cellulose; chitins; chitosans; proteins; aliphatic
polyesters; poly(lactides); poly(glycolides);
poly(e-caprolactones); poly(hydroxybutyrates); poly(anhydrides);
aliphatic polycarbonates; poly(orthoesters); poly(amino acids);
poly(ethylene oxides); and polyphosphazenes. Of these suitable
polymers, aliphatic polyesters and polyanhydrides are preferred. Of
the suitable aliphatic polyesters, poly(lactide) is preferred. The
degradable particulate diverting agents may comprise a
plasticizer.
[0033] In some embodiments, a self-degradable particulate diverting
material which degrades over time may be placed in the subterranean
zone. The self-degradable particulate diverting material comprises
a mixture of a degradable aliphatic polyester and a hydrated
organic or inorganic solid compound. A treating fluid may be
introduced into the subterranean zone and then diverted by the
self-degradable particulate diverting material therein. Thereafter,
the degradable aliphatic polyester in the self-degradable
particulate diverting material is allowed to at least partially
degrade in the releasable water provided by the hydrated organic or
inorganic compound which dehydrates over time when heated in the
subterranean zone. Examples of the hydrated organic or inorganic
solid compounds that can be utilized in the self-degradable
diverting material include, but are not limited to, hydrates of
organic acids or their salts such as sodium acetate trihydrate,
L-tartaric acid disodium salt dihydrate, sodium citrate dihydrate,
hydrates of inorganic acids or their salts such as sodium
tetraborate decahydrate, sodium hydrogen phosphate heptahydrate,
sodium phosphate dodecahydrate, amylose, starch-based hydrophilic
polymers, and cellulose-based hydrophilic polymers. Of these,
sodium acetate trihydrate is preferred. The lactide units of the
aliphatic polyester and the releasable water of the organic or
inorganic solid compound utilized are preferably present in the
mixture in equal molar amounts. The specific amount of the hydrated
compound that may be included will depend upon the presence of
formation water, produced fluids, formation temperature, treating
fluid and production rates.
[0034] Suitable diverting agents may be provided to the
subterranean formation via a carrier fluid that then dissipates
into the subterranean zone, and as a result the degradable
particulate diverting materials is screened out of the carrier
fluid by the formation. A variety of carrier fluids can be utilized
including, but not limited to, water, brines, seawater or formation
water. Of these, in certain embodiments, brines and seawater are
preferred.
[0035] If a diverting agent is used, the amount used may range up
to 3% or more by weight or volume of the carrier fluid. Preferred
diverting agents are disclosed in Halliburton's Published U.S.
Patent Application No. 2004-0261996-A1, entitled Methods of
Diverting Treating Fluids in Subterranean Zones and Degradable
Diverting Materials, filed on Jun. 27, 2003 and published on Dec.
30, 2004, the disclosure of which is incorporated by reference.
[0036] Mechanical diverting agents may also be suitable. These may
include but are not limited to, perf balls, packers, treatment
designs, hydrojetting methods, and methods known as "Surgifrac,"
which are available from Halliburton Energy Services, at various
locations.
[0037] In some embodiments, the fluids of the present invention may
include surfactants, e.g., to improve the compatibility of the
fluids of the present invention with other fluids (like any
formation fluids) that may be present in the well bore or reduce
interfacial tension. Using surfactants may be advisable when liquid
hydrocarbons are present in the well bore. An artisan of ordinary
skill with the benefit of this disclosure will be able to identify
the type of surfactant as well as the appropriate concentration of
surfactant to be used. Suitable surfactants may be used in a liquid
or powder form. Where used, the surfactants are present in the
fluids in an amount sufficient to prevent incompatibility with
formation fluids or well bore fluids. If included, a surfactant may
be added in an amount of from about 1/10th of a gal per 1000 gals
up to 10% by volume. Higher concentrations may be used, e.g., if a
surfactant gelling agent is used, and this amount may be in excess
of 5% in some instances. In an embodiment where liquid surfactants
are used, the surfactants are generally present in an amount in the
range of from about 0.01% to about 10% by volume of a fluid. In one
embodiment, the liquid surfactants are present in an amount in the
range of from about 0.1% to about 10% by volume of the fluid. In
embodiments where powdered surfactants are used, the surfactants
may be present in an amount in the range of from about 0.001% to
about 10% by weight of the fluid. Examples of suitable surfactants
are non-emulsifiers commercially available from Halliburton Energy
Services, Inc., of Duncan, Okla., under the tradenames
"LOSURF-259.TM." nonionic nonemulsifier, "LOSURF-300.TM." nonionic
surfactant, "LOSURF-357.TM." nonionic surfactant, and
"LOSURF-400.TM." surfactant. Another example of a suitable
surfactant is a non-emulsifier commercially available from
Halliburton Energy Services, Inc., of Duncan, Okla., under the
tradename "NEA-96M.TM." Surfactant. It should be noted that it may
be beneficial to add a surfactant to a viscosified treatment fluid
of the present invention as that fluid is being pumped down hole to
help eliminate the possibility of foaming if so desired.
[0038] In some embodiments, the acidizing fluids of the present
invention may be used in conjunction with fluids containing
viscoelastic surfactants.
[0039] In some embodiments, if desired, the fluids of the present
invention may contain bactericides, inter alia, to protect both the
subterranean formation as well as the fluid from attack by
bacteria. Such attacks may be problematic because they may lower
the viscosity of the fluid, resulting in poorer performance, for
example. Bacteria also can cause plugging by bacterial slime
production, and can turn the formation sour. Any bactericides known
in the art are suitable. An artisan of ordinary skill with the
benefit of this disclosure will be able to identify a suitable
bactericide and the proper concentration of such bactericide for a
given application. Where used, such bactericides are present in an
amount sufficient to destroy all bacteria that may be present.
Examples of suitable bactericides include, but are not limited to,
a 2,2-dibromo-3-nitrilopropionamide, commercially available under
the tradename "BE-3S.TM." biocide from Halliburton Energy Services,
Inc., of Duncan, Okla., and a 2-bromo-2-nitro-1,3-propanediol
commercially available under the tradename "BE-6.TM." biocide from
Halliburton Energy Services, Inc., of Duncan, Okla. In one
embodiment, the bactericides are present in the viscosified
treatment fluid in an amount in the range of from about 0.001% to
about 0.003% by weight of the viscosified treatment fluid. Another
example of a suitable bactericide is a solution of sodium
hypochlorite, commercially available under the tradename
"CAT-1.TM." chemical from Halliburton Energy Services, Inc., of
Duncan, Okla. In certain embodiments, such bactericides may be
present in the viscosified treatment fluid in an amount in the
range of from about 0.01% to about 0.1% by volume of the
viscosified treatment fluid. In certain preferred embodiments, when
bactericides are used in the viscosified treatment fluids of the
present invention, they are added to the viscosified treatment
fluid before the gelling agent is added.
[0040] In some embodiments, the fluids of the present invention can
be prepared in any suitable tank equipped with suitable mixing
means well known to those skilled in the art. The fluids may be
transferred either at a controlled rate directly into the well bore
or into a convenient storage tank for later placement down the well
bore. In either event, the pumping rates and pressures utilized
will depend upon the characteristics of the formation and whether
or not fracturing of the formation is desired. After a fluid has
been injected into a well bore, the well may be shut in and allowed
to stand for a period of several hours or more depending on the
type of acid employed and the formation treated. If there is
pressure in the well, pressure then can be released and then the
spent or at least partially spent fluid (that likely contains salts
formed by the reaction of the acid in the subterranean formation),
may be permitted to flow back to the surface for appropriate
disposal. The well then can be placed on production or used for
other purposes.
[0041] Additionally, in some embodiments, the diverting effect of
the acidizing fluids of the present invention may be enhanced by
introducing the fluid into a subterranean formation in stages. The
first stage involves pumping stages of the acidizing fluid
containing an iron crosslinking agent, and then stopping pumping
for a short amount of time to allow an in-situ crosslink to form
before resuming pumping of the treatment fluid. A preferred method
of this would be to use a low strength acid in the shut in stage to
provide a faster crosslink. A preferred range for this would be 1
to 10% acid and a more preferred range would be 2.5 to 7.5% acid.
An acid concentration of about 5% is highly preferred.
[0042] To facilitate a better understanding of the present
invention, the following examples of certain aspects of some
embodiments are given. In no way should the following examples be
read to limit, or define, the entire scope of the invention.
EXAMPLES
[0043] An 80 lb/Mgal xanthan gel ("WG-37" xanthan was used and is
available from Halliburton Energy Services, Inc., in Duncan, Okla.)
was hydrated in water for 30 minutes in a Waring blender, and then
oxidized with 5% by volume sodium hypochlorite (6-7.35% sodium
hypochlorite in water). Upon a short oxidation (approximately 5
minutes) while mixing, hydrochloric acid was added to a
concentration in the final fluid of 15% HCl. Crosslinking agents
were also added. When 2% by volume "CL-23," which is a
zirconium-based crosslinking agent available from Halliburton
Energy Services in Duncan, Okla., was added to an aliquot, a
lipping, live-acid gel was formed. In the case of adding 1% "XL-1"
to an aliquot, which is a iron-based crosslinking agent available
from Halliburton Energy Services in Duncan, Okla. a crosslinked gel
was formed as the acid spent with calcium carbonate.
[0044] Therefore, the present invention is well adapted to attain
the ends and advantages mentioned as well as those that are
inherent therein. The particular embodiments disclosed above are
illustrative only, as the present invention may be modified and
practiced in different but equivalent manners apparent to those
skilled in the art having the benefit of the teachings herein.
Furthermore, no limitations are intended to the details of
construction or design herein shown, other than as described in the
claims below. It is therefore evident that the particular
illustrative embodiments disclosed above may be altered or modified
and all such variations are considered within the scope and spirit
of the present invention. In particular, every range of values (of
the form, "from about a to about b," or, equivalently, "from
approximately a to b," or, equivalently, "from approximately a-b")
disclosed herein is to be understood as referring to the power set
(the set of all subsets) of the respective range of values, and set
forth every range encompassed within the broader range of values.
Also, the terms in the claims have their plain, ordinary meaning
unless otherwise explicitly and clearly defined by the
patentee.
* * * * *